A seismic survey represents an attempt to image or map the subsurface of the earth by sending sound energy down into the ground and recording the “echoes” that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is positioned at various locations near the surface of the earth above a geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected or transmitted, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface, sometimes as a series of closely spaced adjacent two-dimensional lines and in other cases as a grid of source and receiver lines that are arranged to beat some other angle with respect to each other. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data “cube” or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both 2D and 3D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. (Chapter 1, pages 9-89, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2D processing and that disclosure is incorporated herein by reference.) General background information pertaining to 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Yilmaz, the disclosure of which is also incorporated herein by reference.
A seismic trace is a digital recording of the acoustic energy reflecting from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials. The digital samples are usually acquired at 0.002 second (2 millisecond or “ms”) intervals, although 4 milliseconds and 1 millisecond sampling intervals are also common. Each discrete sample in a conventional digital seismic trace is associated with a travel time, and in the case of reflected energy, a two-way travel time from the source to the reflector and back to the surface again, assuming, of course, that the source and receiver are both located on the surface. Many variations of the conventional source-receiver arrangement are used in practice, e.g. VSP (vertical seismic profiles) surveys, ocean bottom surveys, etc. Further, the surface location of every trace in a seismic survey is carefully tracked and is generally made a part of the trace itself (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data—and attributes extracted therefrom—on a map (i.e., “mapping”).
The data in a 3D, survey are amenable to viewing in a number of different ways. First horizontal “constant time slices” may be taken extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a horizontal 2D plane of seismic data. By animating a series of 2D planes it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
One problem that is frequently encountered in seismic data processing is how best to combine seismic data from two independent datasets that have been collected in the same (or a near-by) area so as to create a unified image of the subsurface. It is of critical importance that seismic data that have similar character from line to line so that subtle signal variations may be tracked consistently across multiple surveys. If the two datasets are collected at the same time using the same equipment, combining the data sets may not be a problem. Differences in the survey source (dynamite, vibrator, air gun, etc.), differences in the type of seismic sensors (geophone, hydrophone, etc.), and differences in the recording instrumentation (e.g., the amplifier type/brand) are among the many factors that can cause the character of one seismic data set to differ markedly from another. In these and many other scenarios, it would be advantageous to process one data set or both through some sort of matching algorithm so that the character of the seismic data is as nearly constant as possible where the surveys intersect.
One instance wherein some degree of character matching would be especially important would be where data that were acquired using geophones is to be combined with data that were obtained using hydrophones. Although this might occur in many circumstances (e.g., a combined land/marine survey) for purposes of specificity in the text that follows this situation will be discussed in the context of a multi-component ocean bottom survey (“OBS”, hereinafter). Conventional OBS sensors are readily available that simultaneously record both P and S waves by combining hydrophones and oriented geophones that may be integral to the same physical case. However, comparing and combining data that were obtained via the two types of receivers has proven to be troublesome because of character differences in the signal, noise, etc. In more particular, since the noise level of geophones tends to be higher than that of hydrophones, some sort of matching should be performed if a reliable quality seismic image is to be obtained from the combined data set.
Another instance where matching would be useful would be in the acquisition of 4D seismic data, where the same area is repeatedly surveyed to track the progression of a fluid boundary (e.g., oil/water, oil/gas, etc.) in the survey in a producing field. In this example one goal would be to match the base survey to a subsequent monitoring survey or vice versa. A goal of such a matching would be to enhance the ability to combine and/or compare surveys collected at different times (and possibly with different sources) while maximizing the signal to noise ratio.
Still another example of circumstances when matching could be useful would be in instances where it was desired is to match predicted multiples to true multiples in the seismic data. A good match would make it possible to better suppress the multiples (which are considered noise for standard seismic imaging) which would otherwise tend to obscure the image of the subsurface provided by the data.
Heretofore, as is well known in the seismic processing and seismic interpretation arts, there has been a need for a better method of seismic data matching. Accordingly, it should now be recognized, as was recognized by the present inventor, that there exists, and has existed for some time, a very real need for a method of seismic data processing that would address and solve the above-described problems.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so, because those skilled in the art to which the invention pertains will be able to devise other, forms of this invention within the ambit of the appended claims.